Processes For Producing High Biogenic Concentration Fischer-Tropsch Liquids Derived From Municipal Solid Wastes (MSW) Feedstocks

ABSTRACT

Processes for producing high biogenic concentration Fischer-Tropsch liquids derived from the organic fraction of municipal solid wastes (MSW) feedstock that contains a relatively high concentration of biogenic carbon (derived from plants) and a relatively low concentration of non-biogenic carbon (derived from fossil sources) wherein the biogenic content of the Fischer-Tropsch liquids is the same as the biogenic content of the feedstock.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation of U.S. patent application Ser. No.15/682,368 filed Aug. 21, 2017, entitled PROCESSES FOR PRODUCING HIGHBIOGENIC CONCENTRATION FISCHER-TROPSCH LIQUIDS DERIVED FROM MUNICIPALSOLID WASTES (MSW) FEEDSTOCKS, which is a continuation of U.S. patentapplication Ser. No. 15/077,782 filed Mar. 22, 2016, entitled PROCESSESFOR PRODUCING HIGH BIOGENIC CONCENTRATION FISCHER-TROPSCH LIQUIDSDERIVED FROM MUNICIPAL SOLID WASTES (MSW) FEEDSTOCKS now U.S. Pat. No.9,738,579, which is a divisional of U.S. patent application Ser. No.14/842,729 filed Sep. 1, 2015, entitled PROCESSES FOR PRODUCING HIGHBIOGENIC CONCENTRATION FISCHER-TROPSCH LIQUIDS DERIVED FROM MUNICIPALSOLID WASTES (MSW) FEEDSTOCK, which is a continuation of U.S. patentapplication Ser. No. 14/799,522 filed Jul. 14, 2015, entitled PROCESSESFOR PRODUCING HIGH BIOGENIC CONCENTRATION FISCHER-TROPSCH LIQUIDSDERIVED FROM MUNICIPAL SOLID WASTES (MSW) FEEDSTOCK now Abandoned, whichis a continuation-in-part of U.S. patent application Ser. No. 14/138,635filed Dec. 23, 2013, entitled GAS RECYCLE LOOPS IN PROCESS FORCONVERTING MUNICIPAL SOLID WASTE INTO ETHANOL now U.S. Pat. No.9,458,073, which is a continuation of U.S. patent application Ser. No.13/023,505 filed Feb. 8, 2011, entitled PRODUCT RECYCLE LOOPS IN PROCESSFOR CONVERTING MUNICIPAL SOLID WASTE INTO ETHANOL now U.S. Pat. No.8,614,257, which claims benefit of U.S. Provisional Patent ApplicationNo. 61/302,516 filed Feb. 8, 2010, entitled PROCESSES FOR CONVERTINGMUNICIPAL SOLID WASTE INTO ETHANOL, the disclosure of these applicationsare incorporated by reference hereinto.

The application is further related to the following U.S. patentapplications. U.S. patent application Ser. No. 13/023,497, filed Feb. 8,2011, entitled “Processes For Recovering Waste Heat From GasificationSystems For Converting Municipal Solid Waste Into Ethanol,” which issuedon Dec. 10, 2013 as U.S. Pat. No. 8,604,088 B2, and U.S. patentapplication Ser. No. 13/023,510, filed Feb. 8, 2011, entitled “GasRecycle Loops in Process For Converting Municipal Solid Waste IntoEthanol,” which issued on Dec. 10, 2013 as U.S. Pat. No. 8,604,089 B2.These applications are incorporated by reference hereinto.

TECHNICAL FIELD

The subject matter relates generally to processes, systems, andfacilities for converting municipal solid wastes (MSW) into fuel.

BACKGROUND

Municipal solid waste (MSW) includes all solid materials disposed bymunicipalities. While some of this waste is recycled, the majority istypically dumped in landfills, where it decomposes over a period ofdecades or even centuries. It has been recognized that municipal solidwaste contains organic materials that have energy content. If MSW isleft untreated in landfills, the energy content can be drained slowlyfrom the landfill by bacterial processes, which not only dissipate theconcentrated energy but, also, produce methane, a strong greenhouse gas.Some landfills have sought to collect methane, which may be used forfuel; however, the conversion to methane takes place on long timescales, wastes much of the internal energy of the MSW, and is ratherineffective in recovering much of the available energy content of theMSW.

The earliest and most common method of recovering energy from MSW isincineration. Incineration includes the combustion of MSW orrefuse-derived fuel (RDF) to produce heat, which typically powers aturbine to produce electricity. Byproducts of incineration include flyash, bottom ash, and flue gases containing dangerous pollutantsincluding sulfur compounds, CO2, which is a green-house gas, acid gasesas well as metals, metal compounds and particulates. Fly ash and bottomash are typically discarded in landfills. Some harmful flue gases andparticulates can be scrubbed from the incineration flue stream prior todischarge into the atmosphere.

Another method of recovering energy from MSW is pyrolysis, whichinvolves heating the organic portions of the MSW, so that thermallyunstable compounds are chemically decomposed into other compounds. Thosecompounds mix with other volatile components to form a pyrolysis gasthat typically includes tars, alkenes, aromatic hydrocarbons, sulfurcompounds, steam, and carbon dioxide. The solid residue from pyrolysisprocess includes coke (residual carbon), which can then be burned orused as a gasification feedstock.

A related method for recovering energy from MSW is gasification.Gasification involves converting at least a fraction of the MSW into asynthesis gas (“syngas’) composed mainly of carbon monoxide carbondioxide, and hydrogen. Gasification technology has existed for somecenturies. In the nineteenth century, for instance, coal and peat wereoften gasified into “town gas” that provided a flammable mix of carbonmonoxide (CO), methane (CH₄) and hydrogen (H₂) that was used forcooking, heating and lighting. During World Wars I and II, biomass andcoal gasifies were used to produce CO and H₂ to meet transportationneeds. Sometimes, some of the syngas was converted directly in to liquidtransportation fuels using the Fisher-Tropsch process. With thediscovery of vast quantities of domestic oil and natural gas followingWorld War II, coal and biomass gasification were no longercost-competitive and all but disappeared.

Gasification has been applied directly to the MSW but, in other cases,the MSW is first pyrolyzed, and then subjected to a secondarygasification process. Gasification of MSW generally includes amechanical processing step that removes recyclables and other materialsthat have low or no energy content. Then, the processed feedstock isheated in a gasifier in the presence of a gasification agent (includingat least some oxygen and possibly steam). Gasifiers may have a number ofconfigurations. For example, fixed-bed gasifiers place the feedstock ina fixed bed, and then contact it with a stream of a gasification agentin either a counter-current (“up draft”) or co-current (“down draft”)manner. Gasifiers may also use fluidized bed reactors.

Another method of gasifying MSW is treatment in the presence of oxygenwith a high-temperature plasma. Such systems may convert the MSW tosyngas, leaving vitrified wastes and metals as byproduct.

To create hydrocarbons as synthetic fuels, a known method for convertingsyngas into synthetic fuels is the catalytic Fischer-Tropsch (F-T)process. This process produces a mixture of hydrocarbons which could befurther refined to produce liquid transportation fuels.

With numerous detrimental effects of greenhouse gases being increasinglydocumented, there is a clear need to reduce energy production fromfossil fuels, particularly from petroleum and coal-derived fuel sources.To encourage the reduction of fossil fuel usage, governments arepromoting the usage of fuels derived from renewable organic sourcesrather than fossil-based sources.

The Environmental Protection Agency (EPA) in the United States hasmandated a Renewable Fuel Standard (“RFS”) under which cellulosic-basedfuels generate Cellulosic RINs (renewable identification numbers) whichare a form of compliance credits for Obligated Parties (e.g.,refineries). Under the RFS, the Obligated Parties are required to blendan increasing amount of cellulosic fuel into fossil-derived fuels.

To determine the biogenic percentage content of fuels, the EPA requirestests that use radiocarbon dating methods. More particularly, currentthe USEPA regulations, at Section 8.1426(f)(9), require parties to useMethod B or Method C of ASTM D 6866 to perform radiocarbon dating todetermine the renewable fraction of the fuel.

BRIEF SUMMARY OF THE INVENTION

The present disclosure generally relates to processes and methods forconverting organic materials, such as are contained in MSW, into fuels.More particularly, the present disclosure relates to processes forproducing high biogenic concentration Fischer-Tropsch liquids and therespective upgraded fuel products derived from the organic fraction ofmunicipal solid wastes (MSW) feedstocks that contain relatively highconcentrations of biogenic carbon (derived from plants) and a relativelylow concentration of non-biogenic carbon (derived from fossil sources)along with other non-carbonaceous materials. In practice, the relativelyhigh concentration of biogenic carbon is up to about 80% biogeniccarbon. Particularly noteworthy is that the high biogenic concentrationFischer-Tropsch liquids contain the same relatively high concentrationof biogenic carbon as the feedstock derived from MSW.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated into thisspecification, illustrate one or more exemplary embodiments of theinventions disclosed herein and, together with the detailed description,serve to explain the principles and exemplary implementations of theseinventions. One of skill in the art will understand that the drawingsare illustrative only, and that what is depicted therein may be adapted,based on this disclosure, in view of the common knowledge within thisfield.

Various embodiments, including additions and modifications to theillustrated embodiment, of the present inventions are described hereinin the context of converting feedstock derived from MSW waste intofuels.

In the Drawings:

FIG. 1 shows one embodiment of an overall system for producing highbiogenic concentration Fischer-Tropsch liquids derived from municipalsolid wastes (MSW) feedstock; that contains a relatively highconcentration of biogenic carbon and a relatively low concentration ofnon-biogenic carbons along with other non-carbonaceous materials;

FIG. 2 shows an example of one embodiment of a gasification island;

FIG. 3 shows an example of one embodiment of a syngas conditioningsystem;

FIG. 4A shows an example of one embodiment of a CO2/H2S removal system;

FIG. 4B shows an example of another embodiment of a CO2/H2S removalsystem;

FIG. 5 shows an example of one embodiment of a system for generating F-Tliquids;

FIG. 6 shows an example of one embodiment of a system for producingrefined F-T liquids from the system of FIG. 5.

DETAILED DESCRIPTION

Those of ordinary skill in the art will understand that the followingdetailed description is illustrative only and is not intended to be inany way limiting. Other embodiments of the present inventions willreadily suggest themselves to such skilled persons having the benefit ofthis disclosure, in light of what is known in the relevant arts, theprovision and operation of information systems for such use, and otherrelated areas. Reference will now be made in detail to exemplaryimplementations of the present inventions as illustrated in theaccompanying drawings.

In the interest of clarity, not all of the routine features of theexemplary implementations described herein are shown and described. Itwill of course, be appreciated that in the development of any suchactual implementation, numerous implementation-specific decisions mustbe made in order to achieve the specific goals of the developer, such ascompliance with regulatory, safety, social, environmental, health, andbusiness-related constraints, and that these specific goals will varyfrom one implementation to another and from one developer to another.Moreover, it will be appreciated that such a developmental effort mightbe complex and time-consuming, but would nevertheless be a routineundertaking of engineering for those of ordinary skill in the art havingthe benefit of this disclosure.

Throughout the present disclosure, relevant terms are to be understoodconsistently with their typical meanings established in the relevantart. However, without limiting the scope of the present disclosure,further clarifications and descriptions are provided for relevant termsand concepts as set forth below:

The term municipal solid waste (MSW) as used herein has the same meaningas the term is understood by one of skill in the art. An example of MSWis the solid waste that is obtained from the collection of commercialand household trash. In its raw form, MSW need not be entirely solid, asit may contain entrained or absorbed liquids, or liquids in containersor other enclosed spaces. One of skill in the art will understand thatMSW will have a broad range of compositions, and that the source of MSWneed not necessarily be from a municipality. For purposes of thisdisclosure, other organic waste materials and various biomass materialssuch as vegetative matter, may be equivalent to MSW.

The term stream as used herein means any fluid or solid moving or enroute, directly or indirectly, from one location to another. A stream isstill a stream even if it is temporarily stationary.

Reference to a portion of a stream or material refers to any portion ofthe stream or material, including the stream or material in itsentirety. A portion of a stream or material may be mixed with othercompositions of matter and the mixture will be considered to comprisethe portion of the original stream or material.

The term in fluid communication with as used herein includes withoutlimitation both direct and indirect fluid communication, such as, forexample, through an intermediate process unit.

The term unit as used herein means part of a system, and may for examplecomprise a unit operation, a system or group of unit operations, aplant, etc.

The term syngas (synthesis gas) as used herein has the same meaning asthe term is used by one of skill in the art. For example, syngas maycomprise a combination of carbon monoxide, hydrogen, carbon dioxide andpossibly other components such as, without limitation, water vapor,sulfur- or nitrogen-containing compounds, methane and other alkanes,hydrocarbons, acid gases, halogens and particulates.

The term separator as used herein refers to any process unit known inthe art for performing a separation process and, depending upon context,can include distillation columns, membrane separation systems, ionexchange adsorption systems, thermal adsorption, pressure swingadsorption, molecular sieves, flash drums, absorption or adsorptioncolumns, wet scrubbers, venturi scrubbers, centrifuges, chromatographs,or crystallizers. Separators may separate vapors from liquids, liquidsfrom liquids, vapors from liquids from solids, solids from solids, orfluids from solids.

The term heat exchanger as used herein includes without limitation anyheat exchanger or heat exchange device known in the art, and morebroadly, any device which raises the enthalpy or internal energy of afirst composition of matter, decreases the enthalpy or internal energyof a second composition of matter, and transfers heat from the secondcomposition of matter to the first composition of matter. Various heatexchange means are disclosed herein, all of which are encompassed withinthis term. The term also includes combinations or series of multipleheat exchange means. It includes, without limitation, shell and tubeheat exchangers, air or “fin-fan” coolers, refrigeration units,chillers, cooling towers, steam generators, boilers, plate heatexchangers, adiabatic wheel heat exchangers, plate fin heat exchangers,fluid heat exchangers, waste heat recovery units of any kind, or phasechange heat exchangers of any kind. They may operate in acountercurrent, parallel, crosscurrent configuration, or any other flowconfiguration, and may involve separation of two fluids or directcontact between two fluids, or the use of an intermediate fluid (such aswater, hot oil, molten salt, etc.) to transfer heat from one fluid toanother.

The term compressor as used herein includes anything that is understoodas a compressor in the normal sense of that term. In general, however,the term includes any device that raises a fluid from a first pressureto a second, higher pressure, either adiabatically or non-adiabatically.It may include any kind of compressor or pump, including withoutlimitation, centrifugal or axial, or positive displacement (such asreciprocating, diaphragm, or rotary gear). The term may also include oneor more stages of a multi-stage compressor. The term compressor used inthe singular may also refer to multiple compressors arranged in seriesand/or parallel.

In FIG. 1, the numeral 11 designates an overall system for producinghigh biogenic concentration Fischer-Tropsch liquids derived frommunicipal solid wastes (MSW) feedstock that contains a relatively highconcentration of biogenic carbon and a relatively low concentration ofnon-biogenic carbons along with other non-carbonaceous materials.

At the head of the system 11, a MSW feedstock producing facility,generally designated by the numeral 13, is provided for removingnon-biogenic derived carbon materials and non-carbonaceous materialsfrom MSW to produce a segregated feedstock that contains a relativelyhigh concentration of biogenic carbon and a relatively low concentrationof non-biogenic carbon along with other non-carbonaceous materials foundin MSW.

In the preferred embodiment, the Feedstock Processing Facility 13 willprocess inbound MSW and separate materials into the followingcategories:

-   -   Feedstock Material, sorted from MSW stream to be used for        conversion into fuel;    -   Recoverable Material, including but not limited to ferrous and        nonferrous metals, cardboard, plastics, paper, and other        recyclable materials that can be sorted and shipped to the        commodities markets; and    -   Residual Material, which is the remainder of the material not        recycled or used as feedstock, which can be sent to landfill.

By recovering plastics such as High Density Polyethylene (HDPE) andPolyethylene Terephthalate (PET) among others, the percentage ofnon-biogenic carbon in the feedstock is reduced as the percentage offossil based plastics is reduced. Thus, the feedstock processingfacility functions to provide a highly biogenic feedstock material thatcan be gasified into syngas. For the reasons explained above, thebiogenic percentage content of the feedstock has a significant impact onthe economic value of the cellulosic fuel.

In the feedstock processing unit 13, the waste material may be sized,separated, and processed to remove materials that are not useful in theprocess, or which might reduce its efficiency. For example, the systemremoves metals, inorganic materials, and wet materials such as foodwaste or agricultural products. Such materials may, for example, berecycled or sent to a landfill. Some of the food waste and agriculturalmaterials which are high in biogenic content could be dried and addedback to the feed stream along with other materials.

As indicated in the drawing, the Feedstock Processing Facility 13 can bephysically separate facility from the other portions of the system shownin FIG. 1. As an example, the Feedstock Processing Facility 13 can be asdescribed in co-pending U.S. patent application Ser. No. 14/138,635 forProduct Recycle Loops in Process for Converting Municipal Solid Wasteinto Ethanol, the disclosure of which is incorporated herein byreference.

Although the feedstock may vary greatly in composition, example nominalvalues for the composition of the material remaining after the feedstockis recycled and sorted are listed in Table 1 below.

TABLE 1 Example Ultimate Chemical Composition of Feedstock Approx.Weight Feedstock Constituent (Percent) C 45.4 H 5.7 O 33.8 N 0.7 S 0.11CI 0.09 Ash 4.21 Metal 1.4 H₂0 8.6

The residual materials preferably excluded by the processing, storage,and handling process may include, for instance, metals, rocks, dirt,glass, concrete, and PVC. Preferably, under normal conditions, thereject rate will run between about 10% and about 55% of the total feedrate to the material processing unit. Preferably, they will beindividually separated from the feedstock, deposited in a container, andtransported to a landfill or composting operation, or sent for recyclingor disposal off-site in accordance with applicable governmentalregulations.

An important point is that a bio-refinery, generally designated by thenumeral 17, is fed with a stream 15 containing relatively highconcentration of biogenic carbon and the relatively low concentration ofnon-biogenic carbons along with other non-carbonaceous materials fromthe municipal solid wastes. In practice, the relatively highconcentration of biogenic carbon is up to about 80% biogenic carbon.

The remainder of the system depicted in FIG. 1 is the bio-refinery 17for converting the stream 15 of processed feedstock into a stream 19 ofFischer-Tropsch liquids. Particularly noteworthy is that the highbiogenic concentration Fischer-Tropsch liquids contain the samerelatively high concentration of biogenic carbon as the input stream 15.In other words, percentage-wise, no non-biogenic carbon is added to theFischer-Tropsch liquids in the production system and, indeed, some maybe eliminated.

In the illustrated embodiment, the bio-refinery 17 includes agasification system, generally designated by the numeral 21 andsometimes referred to herein as the Gasification Island (GI), forconverting feedstock derived from MSW into syngas and further processingthat syngas through a hydrocarbon reformer (HR), as will describedbelow, to generate a high biogenic content syngas. It should be notedthat the gasification system 21 receives streams 231 and 235 that carryrecycled hydrocarbon products and intermediate products, respectively,to the HR. Also, the GI 21 receives a stream 27 that carries recycledCO2 to its stage 1 and stage 2, both of which will be described indetail below. Also as will be explained further below, the recycled CO2is used for moderating the water-gas-shift reaction within the steamreformer in the GI 21 and as a purge gas for instruments, instrumentsystems and MSW feeder systems. Further, the GI 21 receives stream 273of oxygen and a stream 25 of F-T tail gas.

In the gasification island 21, generally speaking, the biogenic carbonis converted into biogenic syngas by a combination of steam reforming,sub-stoichiometric carbon oxidation and hydrocarbon reformation. Thesyngas product, including CO, H2 and CO2, is carried by stream 29 in theillustrated embodiment. The gasification reactions occurring in the GI21 will be further described below.

The syngas stream 29 is processed in a syngas conditioning system 41, aswill be described in more detail below, to provide a syngas feed stream31 to an F-T reactor system 33. It should be noted that the syngasconditioning system 41 provides the CO2 recycle stream 27 for recyclingCO2 back to the GI 21.

The output from the F-T reactor system 33 comprises F-T fluids,including a Medium Fischer Tropsch Liquid (MFTL) stream 520 and a HeavyFischer Tropsch liquid (HFTL) stream 540, both of which are F-Thydrocarbons. Any unreacted syngas can be recycled in the F-T reactor 33as will be described below. Further, the output of the F-T reactorsystem 33 includes the afore-mentioned stream 25 of F-T tail gas.

The bio-refinery includes a hydrogen recovery system to remove hydrogenthat is needed for upgrading from the conditioned syngas. A portion ofthe conditioned syngas flows through a combination membrane/PSA unit toyield a high purity hydrogen stream for the upgrading unit. Therecovered hydrogen (permeate) from the membrane is fed to a PSA unit andthe retentate is combined with bypass syngas and fed forward to the FTreactor. The recovered hydrogen is fed to the PSA unit where arelatively pure hydrogen stream is produced (>99.5% H2 ) and the PSAreject stream is routed to the suction of the syngas compressor forrecovery of the reject syngas.

The bio-refinery 17 in FIG. 1 further includes an upgrading system 54for receiving the F-T fluids from the F-T system 33. In the illustratedembodiment, both the Heavy Fischer Tropsch liquid (HFTL) stream 540 andthe Medium Fischer Tropsch Liquid (MFTL) stream 520 are fed to theupgrading system 54. The F-T liquids output liquid from the upgradingsystem 54 is carried by the stream 58 in the illustrated embodiment. Inpractice, the F-T liquids can include naphtha, diesel, SyntheticParaffinic Kerosene (SPK), heavier alkanes along with iso-alkanes,oxygenates, and olefins or combinations of all of these components.Other outputs from the upgrading system 54.are the aforementioned stream231 of naphtha and the stream 233 of off gas.

The gasification island system 21, as shown in detail in FIG. 2,implements a 3-stage gasification process. In the preferred embodiment,the 3-stage gasification process includes:

a. Stage 1—steam reforming;

b. Stage 2—sub-stoichiometric carbon oxidation to gasify unreactedcarbon after steam reforming; and

c. Stage 3—hydrocarbon reforming.

In the illustrated embodiment, the gasification unit, generallydesignated by the numeral 211, includes stage 1 and 2 units, generallydesignated by the numerals 251 and 271, respectively. It can beunderstood that unit 251 is a steam reformer wherein gasification isaccomplished. Further it can be understood that unit 271 is a carbonoxidation system wherein unreacted carbon from the stage 1 gasificationis converted into syngas sub-stoichiometrically. Also in thegasification island 21, hydrocarbon reforming is provided in a thirdstage by a hydrocarbon reforming system generally designated by thenumeral 215.

Steam reformer 251 selectively receives the stream 15 of processedfeedstock and produces a stream 219 of syngas. Also, the gasificationunit 211 receives streams 27 of recycled CO2. In the gasification unit211, the recovered high biogenic CO2 in stream 27 can be used to assistin fluidizing the bed materials, moderating the water-gas-shift reactionand purging instruments in the steam reformer 251, in thesub-stoichiometric carbon oxidation unit 271 and in the hydrocarbonreformer 215. Also, the recovered high biogenic CO2 in stream 27 can beadded to stream 15 of processed feedstock as shown.

As mentioned above, the gasification unit 211 in the embodiment of FIG.2 includes the steam reformer 251 and the sub-stoichiometric carbonoxidation unit 271. It is the steam reformer 251 that initially receivesthe steam 15 of processed feedstock. Also, it is the steam reformer 251that initially receives the steam 273 of oxygen. Preferably, the steamreformer 251 includes an indirect heat source 253. The output streamsfrom the steam reformer 251 include a stream 254 of syngas and a stream256 of solids. The syngas stream 254 is carried to the hydrocarbonreforming unit 215 with the stream 219. The solids stream 256, primarilycomprised of ash and fine char, is carried to the sub-stoichiometriccarbon oxidation unit 271.

In the preferred embodiment, the steam reformer 251 is a fluidized bedsystem that utilizes superheated steam, CO2, and O2 as thebed-fluidizing medium. In another embodiment only steam and 02 are usedas a bed-fluidizing medium. Preferably, externally-fired indirectheaters 253 maintain the reformer bed temperature and provide much ofthe energy to support the endothermic reactions required in thegasification process. The process gas stream can exit the steam reformer251 through a series of cyclones. Preferably, an internal cycloneseparates and returns the majority of any entrained bed media to thereformer fluidized bed while a second external cyclone collectsunreacted char for further conversion to syngas in thesub-stoichiometric carbon oxidation unit 271. Preferably, flue gas fromthe steam reformer's indirect heaters is used in a fire tube boiler togenerate steam for plant use.

The illustrated hydrocarbon reformer unit 215 receives the syngas stream219 and produces the afore-mentioned primary stream 29 of syngascontaining CO, H2 and CO2 along with trace constituents. Further, thehydrocarbon reformer unit 215 receives stream 273 of oxygen and stream25 of F-T tail gas. Finally, the hydrocarbon reformer unit 215 receivesthe aforementioned streams 231 of naphtha and 233 of off gas.

The hydrocarbon reformer unit 215 operates to recover the biogeniccarbon by thermally dissociating hydrocarbons at temperatures greaterthan 2200 degrees F. Heat for the hydrocarbon reformer is provided byoxidation of carbon monoxide and hydrogen. It may be noted that thesereactions are exothermic.

The hydrocarbon reformer unit 215, in the embodiment of FIG. 2, includesa syngas cooling section 225. The syngas cooling section can comprise,for example, a radiant slagging cooler or a recycle syngas slaggingquencher.

In preferred practice, the hydrocarbon reforming unit 215 is arefractory-lined vessel with oxygen gas burner/mixer which operates inthe range of 1800° F. to 3000° F. to assure all hydrocarbon compounds inthe gas stream, including tars are converted to syngas, sulfur compoundsare converted to H₂S, and the water gas shift reactions approachequilibrium. In the hydrocarbon reforming unit 215, the F-T tail gaspurged from the F-T reaction loop, the purification system off gas, andstream 231 of vaporized naphtha are converted back to CO and H₂.

The sub-stoichiometric carbon oxidation unit 271, in addition toreceiving the solids stream 256, receives the stream 27 of recycled CO2stream and a stream 273 of oxygen. Heating in the carbonsub-stoichiometric oxidation unit 271 is provided by sub-stoichiometricoxidation of the unreacted carbon. A stream 275 of low pressure steam issuperheated in the sub-stoichiometric carbon oxidation unit and used asfluidization steam for both stage 1 and stage 2 gasification. The outputof the sub-stoichiometric carbon oxidation unit 271 is syngas stream 277which, in the illustrated embodiment, joins with the syngas stream 254from steam reformer 251 to form syngas stream 219 which is fed to thehydrocarbon reformer unit 215.

In the preferred embodiment, the sub-stoichiometric carbon oxidationunit 271 utilizes a fluidized bed in which oxygen is added with thefluidization steam and CO2 to further convert fine char to syngas. Thegasses generated in and passing through the sub-stoichiometric carbonoxidation unit 271 pass through an external cyclone and re-enter themain syngas stream 219. Preferably, the ash removed in the cyclone iscooled and transported to a collection silo for offsite disposal. Heatexchangers, submerged in the fluid bed of the sub-stoichiometric carbonoxidation unit 271 remove some heat by superheating low-pressure steamto 1100° F. for use in the fluidization bed steam reformer 251 and thefluidization bed of the unit 271 itself.

In operation of the system of FIG. 2, within the fluidized bed of thesteam reformer 251, externally fired heaters rapidly heat thecirculating bed media and the feedstock entering the vessel. Almostimmediately, the feedstock undergoes drying and pyrolysis, therebycreating gaseous and solid (char) products. The gaseous pyrolysisproducts undergo water-gas shift reactions and together withsimultaneous steam reforming of the solid char material, produce asyngas primarily made up of H2, CO, CO2, and some hydrocarbons. Mostremaining char reacts with superheated steam and oxygen to producesyngas. Char that escapes the steam reformer is separated via a cycloneand dropped into the sub-stoichiometric carbon oxidation unit foradditional gasification and conversion. The steam reformer and thesub-stoichiometric carbon oxidation unit utilize internal and externalcyclones to separate and retain bed media that becomes entrained in theprocess gas stream. From the steam reformer 251 and thesub-stoichiometric carbon oxidation unit 271, the syngas flows viastream 219 to the hydrocarbon reformer unit 215 to convert any remainingchar, hydrocarbons, and tars into syngas.

As mentioned above, the output of the hydrocarbon reformer unit 215 isthe syngas stream 29 which is fed to the syngas conditioning system 41which will now be described in conjunction with FIG. 3.

As shown in FIG. 3, the exemplary syngas conditioning system, which hasbeen generally designated by the numeral 41, receives the primary syngasstream 29 and conditions that stream to produce the gaseous feed stream31 to F-T reactors. In the illustrated embodiment, the syngasconditioning system 41 includes, sequentially in fluid flowcommunication, a Syngas Heat Recovery Steam Generator (HRSG) unit 411for waste heat recovery, a syngas scrubber unit 421, a syngas compressor431, a primary guard bed 436, a water gas shift reactor 441, ammoniaremoval unit 446, secondary guard beds 451, and a CO2/H2S removal system461. One output of the CO2/H2S removal system 461, in the illustratedembodiment, is a syngas feed stream 470. Another output of the CO2/H2Sremoval system 461 is the stream 27 of recycled CO2.

As can be seen from the drawings, steam is generated from severalsources inside the process. A HRSG recovers steam from the flue gasgenerated in the indirect fired heater unit 253 in the steam reformerunit 251. Steam is also generated in the HRSG unit 411 that recoversheat from the syngas stream 29 leaving the gasification island and steamis generated in the power boiler. The steam from all three sources arecombined and superheated to provide the medium pressure steam used asthe motive fluid in either syngas compressor (unit 431) steam turbine ora steam turbine power generator (FIG. 1). The combined medium pressuresteam can have a biogenic content equal to the MSW feed depending on thequantity of natural gas used in firing the external heaters. In thepreferred embodiment a portion of the generated syngas is fed to a gasturbine/steam turbine (combined cycle power plant) to generate a highbiogenic content power that is used to supply the electrical demand ofthe plant. In another embodiment, all of the syngas is used to generatesteam for biogenic power and to drive the syngas compressor unit 431with a steam turbine drive.

The syngas scrubber unit 421 is a conventional gas scrubbing device thatreceives the syngas stream 420 and a stream 424 of caustic or othersuitable alkaline solution. The liquids removed from the scrubber unit421 comprise sour water stream 426 which can be conveyed to a wastewatertreatment system. The sour water may contain undesirable contaminantssuch as, for example, ash particles, acids, mercury, and acidiccompounds such as hydrochloric acid (HCl) and hydrogen sulfide (H2S)that are removed from the syngas. Thus, t camn be appreciated that thesyngas scrubber unit 421 is provided to remove contaminants that canpotentially damage downstream equipment and affect the F-T synthesiscatalyst performance.

Preferably, the syngas scrubber unit has three primary sections—aventuri scrubber, a packed tower section, and a direct contact coolersection. If a syngas quench cooler is utilized then approximately halfof the cleaned syngas leaving the syngas scrubber unit will becirculated back to the hydrocarbon reformer quench cooler via the quenchblowers while the remaining half will be compressed in the syngascompressor 431 to meet the requirements of the F-T synthesis process. Ifa radiant slagging cooler is employed the recycle gas blower will not berequired and the flow into the scrubber will equal the flow leaving thegasification island 21. Syngas scrubbing is further described inco-pending U.S. patent application Ser. No. 14/138,635, the disclosureof which has been incorporated herein by reference. The scrubbed syngasis conveyed in stream 428.

In the illustrated embodiment, a syngas compressor stage 431 comprisingone or more conventional compressor stages 433 arranged in series toraise the pressure of a compressor inlet stream comprising at least aportion of the syngas stream to a predefined level, thereby outputting acompressed syngas stream 434. In practice, the final pressure of thesyngas stream 434 may range between about 400 psig to about 600 psig tomeet the process requirements of the F-T synthesis process. Preferably,the heat of compression is removed with intercoolers after all but thefinal stage with all condensed water being collected and sent to thewaste water treatment plant for recovery. The outlet of the compressoris sent hot to primary guard bed 436 where any COS and HCN is hydrolyzedto H2S and NH3 and then to the shift reactor 441.

In one embodiment, the syngas compressor drive is anextraction/condensing turbine that is driven by superheated highpressure steam with a portion of the steam extracted at low pressure forprocess requirements. Also, the F-T recycle compressor (unit 511 in FIG.5) can be on the syngas compressor shaft and driven by the syngascompressor steam turbine drive. In another embodiment the syngascompressor is driven by an electric motor which is energized from thepower generated in a combined cycle power plant using syngas as a fuelto produce high biogenic power.

As also shown in FIG. 3, the water gas shift reactor 441 receives aportion of the pressurized primary syngas stream 440 to shift some ofthe steam and CO into H2 and CO2 via the water gas shift reaction untilthe required H2/CO ratio in the outlet stream 450 is met. Subsequently,a side stream 442 of the pressurized primary syngas may bypass the watergas shift reactor 441 and may be recombined with an outlet stream 450from the water gas shift reactor 441. High pressure steam is generatedin the water gas shift unit to remove the shift heat of reaction. Thegenerated steam is fed back into the syngas stream 440 feeding thereactor to provide the hydrogen source for the shift reaction. Anyadditional steam required can be provided by the plant steam system.

In the embodiment of FIG. 3, the outlet stream 450 of syngas from thewater gas shift reactor 441 is provided to a conventional ammoniaremoval unit 446. In the ammonia removal unit 446, the syngas is cooleduntil the excess water condenses out with absorbed ammonia. Then, thesyngas leaves the condenser 446 as stream 448. The sour water from thecondenser 446 can be conveyed to a wastewater treatment system. Thestream 448 is conveyed to the inlet of the second guard bed 451 whereany volatilized Hg is removed.

As further shown in FIG. 3, the pressurized primary syngas from thesecond guard beds 451 is conveyed as a stream 460 to the CO2/H2S removalsystem 461. The CO2/H2S removal system 461 will be further described inconjunction with FIGS. 4A and 4B. One output of the CO2/H2S removalsystem 461 is a stream 464 of sulfur. Another output is a stream 470 ofsyngas from which sulfur has been removed. The third output is the CO2recycle stream 27.

In the illustrated embodiment of FIG. 3, the syngas feed stream 470 isconveyed to H2S and final guard arsine beds 471 and, then, to an H2recovery unit 481.

Syngas from the H2S/Arsine guard beds flows into the hydrogen recoveryunit 481. The hydrogen recovery unit 481 extracts a steam 482 of highpurity H2 which is required for the Hydrocracking Upgrading process, asdescribed below. The output of the H2 recovery unit 481 is the syngasfeed stream 31 to the F-T reactor 33. A third output from the hydrogenrecovery unit 481 is a stream 483 of rejected syngas. The stream 483 canbe recycled to join the stream 428.

In the preferred embodiment, the hydrogen recovery unit (HRU) 481extracts H2 using a combination membrane and pressure swing adsorption(“PSA”) system. The HRU membrane retentate gas is re-mixed with the bulksyngas stream and sent to the F-T Liquids Reactors. The HRU PSA purgegas is routed to the suction of the Syngas Compressor 431 and thepurified H2 stream 482 is sent to upgrading.

As illustrated in FIG. 5, a system 33 for generating F-T liquidsreceives the syngas feed stream 31. The system includes one or more F-Treactors 533 and provides, as mentioned above, the fluids output stream535 that comprises F-T liquids and F-T tail gas. The F-T reactor outputstream 535 is fed into a thermal separation system generally designatedby the numeral 500 to separate the F-T liquid into its heavy F-T liquid(HFTL), medium FT liquid (MFTL), water and the F-T tail gas.

In the preferred embodiment as illustrated in FIG. 5, the thermalseparation system 500 includes two condensers 501 and 531 and twoseparators 503 and 504. The HFTL separator 503 has outlets 518 and 520,respectively. In practice, the condenser 501 operates using a temperedhot water loop as the cooling medium to condense and separate the HFTLliquid fraction from the F-T water and MFTL liquid fraction. Both theMFTL Water and the FT Tail gas remain in a vapor phase. The HFTL streamis carried by the outlet 520 for storage in tank(s) 521 for furtherprocessing. In practice, the HFTL stream 520 is composed primarily ofheavy hydrocarbon waxes which are solid at room temperature. These waxesare kept warm above 230° F. to prevent solidification.

Also as illustrated in FIG. 5, the thermal separation system 500includes the second condenser 531 that receives, via the stream 518 fromthe HFTL separator 503, the F-T water and MFTL. In practice, the secondcondenser 531 uses cooling water to condense and separate the F-T waterand MFTL from unreacted syngas and non-condensable hydrocarbons (i.e.,methane, etc.). The condensed F-T water and MFTL stream phase split inthe second separator 504, with the MFTL stream routed to storage unit(s)522 via stream 540 and the F-T water routed to waste water treatment viaa stream 542.

As FIG. 5 further shows, the F-T tail gas can be recycled to the F-Treactors 533 via a stream 537. In the illustrated embodiment, the F-Ttail gas is separated at the MFTL separator 504 and carried by stream550 to a compressor 511 whose output is conveyed on the syngas recycleline 537. Prior to the recycle compressor 511, a purge stream 552branches off of stream 550. The purge stream 552 can be directed to boththe hydrocarbon reformer 215 via stream 25 (FIG. 2) to controlhydrocarbon content in the recycle syngas and to the power boiler topurge inerts from the recycle syngas.

FIG. 6 shows an example of one embodiment of the upgrading system 54 ofFIG. 1. More particularly, this figure illustrates a system forproducing refined F-T liquids from the system of FIG. 5. The illustratedsystem includes a hydrocracker reactor unit 643 which receives liquidsfrom hydrocracking charge vessel 524 fed by the aforementioned tanks 521and 522 (FIG. 5). In the preferred embodiment, the hydrocracker reactorunit 643 employs a high temperature, high pressure catalytic processthat upgrades the HFTL and MFTL hydrocarbon streams into atransportation fuel (SPK or Diesel). Due to the low severity of theupgrading, the hydro-processing and hydrocracking occur in one reactor.The olefins and alcohols are first saturated and then the alkanes arecracked into the SPK range of products. The hydrocracking mechanism,which involves a protonated cyclopropane intermediate, forms an isomerproduct along with a straight chained product. In the hydrocrackerreactor unit 643, the feed mixture passes through a series of catalystbeds for conversion into shorter chained hydrocarbons.

In an alternative embodiment, the pre-fractionate the MFTL can bepre-fractionated and there can be removal of the light fraction overheadto the hydrocarbon reformer; then, the heavy fraction along with theHFTL would be conveyed to the hydrocracker for upgrading. Thisembodiment removes most of the oxygenates from the stream flowing to thehydrocracker and lessens the hydrotreating load on the hydrocracker.

As further illustrated in FIG. 6, the hydrocracker reactor unit 643provides the output stream 644 which is fed to a hydrocarbon thermalseparation system generally designated by the numeral 701 wherein thecrackate is cooled, condensed, and separated into two separate heavy andlight crackate streams, using a series of heat exchangers and separatorvessels.

In the illustrated embodiment of the, hydrocarbon thermal separationsystem 701, the crackate is cooled in a feed/effluent heat exchanger 702and the heavy crackate is separated from the light crackate in a heavycrackate separator 703. From the heavy crackate separator 703, the heavycrackate syncrude is routed to a fractionator 853, as by streams 704 and750. In addition, some of the heavy crackate can be recycled to thehydrocracker 643 to keep material flowing into the hydrocracker duringstartup and when the fractionation column is malfunctioning.

In the illustrated embodiment, a light crackate separator 705 isprovided for separating the light crackate from heavy crackate water andhydrogen. The separated light crackate is routed to the fractionator 853by stream 750. The heavy crackate water is sent, as by line 706, to thebio-refinery's waste water treatment plant for treatment. The separatedhydrogen gas is routed to recycle as by streams 708. 741 and 742.

The fractionation process in FIG. 6 will now be described in greaterdetail. As previously mentioned, the fractionator 853 receives a stream704 of heavy crackate liquids and a stream 750 of light crackateliquids. The purpose of the fractionator 853 is to separate the SPK orDiesel cut from the heavy crackate fraction and the naphtha fraction.The side draw stream 856 is fed into a stripper column 857 to removelights from the SPK/Diesel feed and provide final clean up and recoveryof the SPK/Diesel products. In the fractionator 853, the incoming heavyand light crackate streams are combined and heated by natural gas firedheater for an initial separation in the fractionator column. Preferably,the fractionator 853 uses direct steam injection to strip the lowboiling hydrocarbons from the high boiling hydrocarbons withoututilizing a high temperature reboiler configuration.

The outputs from the fractionator 853 include overhead stream 23 thatcarries recyclable hydrocarbon products. Preferably, the overhead stream823 which is provided into a condenser unit 860 where the stream iscondensed and separated into three streams: main fractionator (“MF”)water stream 862, the afore-mentioned light phase (naphtha) stream 231,and offgas stream 233. In practice, the naphtha can be refluxed backinto the fractionator 53 and/or sent to a Naphtha Vaporizer forinjection into the hydrocarbon reformer. The offgas stream 233 isrecycled by the off gas compressor to the hydrocarbon reformer forreprocessing. The bottoms from the fractionator column 853 are pumped tothe hydrocracking charge vessel 560, as by stream 855, for additionalhydrocracking. MF Water is sent to the bio-refinery's wastewatertreatment plant for treatment.

Naphtha from the Fractionator OH Separator is pumped into the NaphthaVaporizer where it is vaporized using low-pressure steam. The naphthavapor then flow into the hydrocarbon reformer 215 of FIG. 2 forrecovery. The fractionation column overhead pressure floats on theoffgas Compressor discharge rate. The offgas Compressor provides motiveforce to move the Fractionator Overhead Separator offgas into thedischarge of the Naphtha Vaporizer. The combined streams then flow intothe hydrocarbon reformer.

The SPK product, withdrawn by the steam 856 from the upper part of thefractionator 853, is sent to the Product Stripper column 857 for finalproduct separation. The heat to the product Stripper column 857 isprovided, for example, by a natural gas fired Product Stripper Reboiler.The Product Stripper overhead stream recycles back to the Fractionator853. The bottoms stream 800 is cooled and sent, via the stream 58, tostorage unit 803 as the SPK product.

As shown in FIG. 4A, one embodiment of an exemplary CO2/H2S removalsystem 461 includes a sulfur removal unit 463 that receives the stream460. One output of the sulfur removal unit 463 is a stream 464 ofsulfur. Another output of the removal unit 463 is a stream 466 of syngasfrom which sulfurs have been removed.

The syngas stream 466 is fed to an amine solvent system, generallyindicated by the numeral 491. In the illustrated embodiment, the aminesolvent system 491 A comprises an absorber unit 493 and a regeneratorunit 495 connected in counter-current relationship. The output of theregenerator unit 493 is the aforementioned syngas feed stream 470. Theoutput of the absorber unit 495 is the aforementioned stream 27 ofrecycled CO2.

In the preferred embodiment of FIG. 4A, the absorber unit 493 is acolumn where CO2 is removed by contact with a circulating amine/watersolution. In this embodiment the amine absorber can remove H2S fromstream 466 in the event the sulfur removal unit under performs. Thetreated syngas is water washed to remove any entrained amine solution.In the preferred embodiment, the cleaned syngas leaving the solventabsorber 493 is heated using Medium Pressure (MP) saturated steam androuted, as stream 470, to the guard bed to removal trace H2S and arseniccatalyst poisons prior to introduction into the F-T synthesis process.

As shown in FIG. 4B, another exemplary CO2/H2S removal system 461includes an amine unit where syngas stream 460 is fed to an aminesolvent system, generally indicated by the numeral 491B. In theillustrated embodiment, the amine solvent system 491B comprises anabsorber unit 493 and a regenerator unit 495 connected incounter-current relationship. The output of the regenerator unit 495 isfed to the sulfur removal unit 463. The output of the absorber unit 493is the aforementioned syngas feed stream 470. In this embodiment, theabsorber unit 493 is a column where CO2 and H2S is removed by contactwith a circulating amine/water solution. The treated syngas is thenwater washed to remove any entrained amine solution and sent, as stream470, to the final guard beds 471.

In embodiment of FIG. 4B, the regenerator overhead output stream 466 isfed to the sulfur removal unit 463 where the H2S is removed from thereject CO2 stream. One output of the sulfur removal unit 463 is theaforementioned stream 27 of recycled CO2 and a stream 464 of sulfur. Aportion of the overhead CO2 reject stream from the Sulfur Removal unitis compressed and recycled back the gasification island and the excessis vented to the atmosphere.

In operation of CO2/H2S removal system in FIGS. 4A and 4B, “rich” amine(i.e., amine after absorption of CO2 ) from the absorber column passesthrough a lean/rich exchanger and then flashes into the Rich SolventFlash Drum. The flashed gas, rich in CO and H2, flows to the suction ofthe syngas compressor for reuse in the process. The flashed rich liquidstream flows to the Solvent Regenerator column. In the SolventRegenerator, the rich solvent is heated in a steam reboiler, driving offthe absorbed CO2/H2S. The “leaned” solvent flowing out the bottom of theSolvent Regenerator is recirculated back via the lean/rich exchanger andthe solvent cooler to the Absorber for reuse. A portion of the overheadCO2 reject stream from the Solvent Regenerator is compressed andrecycled back the gasification island and the excess is vented to theatmosphere. Preferably, the system is designed to reduce the CO2 contentin the syngas stream to <1 mol % and the H2S content to <5 ppmv, whileminimizing the loss of CO and H2.

In the overall operation of the above-described system, multiplereactions take place as MSW is gasified. The major reaction occurs atelevated temperatures when char (carbon) reacts with steam to producesyngas primarily made up of hydrogen (H2), carbon monoxide (CO), carbondioxide (CO2), and some hydrocarbons:

C+H2O→H2+CO

2C+O2→2CO

C+O2→CO2

Simultaneously, the reversible “water gas shift” reaction

CO+H2O↔CO2+H2,

approaches equilibrium conditions with the CO/H2O and the CO2/H2 ratiosbased on the equilibrium constant at the gasifier operating temperature.The gasification system may be configured, and conditions provided, sothat at least the following gasification reaction occurs:

C+H2O→H₂+CO.

Simultaneously, conditions may preferably be provided so that thefollowing reversible “water shift” reaction reaches an equilibrium statedetermined mainly by the temperature of the gasifier, the pressurepreferably being near atmospheric:

CO+H₂O↔CO₂+H₂.

The primary FT reaction converts syngas to higher molecular weighthydrocarbons and water in the presence of a catalyst:

nCO+(2n+1)H₂→C_(n)H_(2n+2)+nH₂O.

Further as to the overall operation of system, it should be noted thatthe syngas produced in the gasification island 21 has an insufficientquantity of hydrogen for the effective production and upgrading of F-Tliquids. The Sour shift reactor 441 generates additional hydrogen toincrease the H₂:CO ratio in the syngas from about 0.8 to approximately2.0. The water gas shift reaction converts a portion of the CO and H₂Oin the syngas to H2 and CO₂. The reaction is exothermic and occurs overa sour shift catalyst. The reaction is a “sour shift” as H2S is stillpresent in the syngas stream. Utility steam and steam generated by theShift Reactor 441 are mixed with the syngas to provide the water for thewater-gas shift reaction and to moderate the temperature rise in thereactor. Hydrogen production and the syngas H₂:CO ratio are controlledby bypassing a portion of the syngas stream around the Shift Reactor.The Shift Reactor effluent heat is recovered by interchanging with thereactor influent syngas, generating shift reactor steam, and pre-heatingboiler feed water.

The creation of fuel from MSW by the above-described system hassignificant advantages. It provides an energy efficient system with avery low emissions profile, reduces MSW entering landfills (thusdramatically reducing harmful methane gas emissions from landfills andmitigating the need for new or expanded landfills), reduces bydisplacement greenhouse gases associated with the use of petroleum andcoal derived fuel products. The system increase the biogenic content ofcellulosic-based fuels and, therefore, substantially increases the valueof such fuels.

Exemplary embodiments have been described with reference to specificconfigurations. The foregoing description of specific embodiments andexamples has been presented for the purpose of illustration anddescription only, and although the invention has been illustrated bycertain of the preceding examples, it is not to be construed as beinglimited thereby.

What is claimed is:
 1. A process for producing a transportation fuel orfuel additive derived from municipal solid wastes (MSW) that containmaterials that are produced from biogenic derived carbon materials andnon-biogenic derived carbon materials, the process comprising the stepsof: a) in a feedstock processing step, removing some of the non-biogenicderived carbon materials and non-carbonaceous materials from municipalsolid wastes to produce a processed MSW feedstock that contains a higherconcentration of biogenic carbon materials than non-biogenic carbonmaterials; and b) converting the processed MSW feedstock intoFischer-Tropsch liquids in a bio-refinery while maintaining a greaterconcentration of biogenic carbon than non-biogenic carbon; and c)upgrading the Fischer-Tropsch liquids into a transportation fuel or fueladditive while maintaining a greater concentration of biogenic carbonthan non-biogenic carbon.
 2. The process according to claim 1 whereinthe step of converting the processed MSW feedstock into Fischer-Tropschliquids in the bio-refinery, further comprises: converting the processedMSW feedstock in a gasification island.
 3. The process according toclaim 1, further comprising the step of: in a power generation process,converting some or all of the biogenic carbon material into biogeniccarbon derived power.
 4. The process according to claim 1 wherein in thefeedstock processing step, more than about 10% of the non-biogenicderived carbon materials are removed.
 5. The process according to claim1 wherein in the feedstock processing step, up to about 80% of thenon-biogenic derived carbon materials are removed.
 6. The processaccording to claim 1 wherein in the feedstock processing step, betweenabout 10% and 90% of the non-biogenic derived carbon materials areremoved.
 7. The process according to claim 1, the converting step beingcomprised of three stages carried out in a gasification island: 1) steamreforming the processed feedstock in a steam reformer configured to dry,volatilize and gasify the processed feedstock to produce syngascontaining CO, H₂, H₂O and CO₂, unreacted char, inert solids andunreacted hydrocarbons; 2) further gasifying in a sub-stoichiometriccarbon oxidation unit configured to gasify the unreacted char from thesteam reformer; and 3) hydrocarbon reforming in a hydrocarbon reformingunit configured to convert remaining char, hydrocarbons and tars intosyngas.
 8. The process according to claim 7, further comprising:conditioning the syngas in a syngas conditioning unit configured toreceive the syngas from the gasification island and remove contaminants,remove/recover CO2 and provide a high biogenic CO2 recycle stream forrecycling high biogenic CO2 to the gasification island for biogeniccarbon conservation and to adjust the H₂:CO₂ ratio in the syngas to apredetermined value; and converting the syngas into Fisher-Tropschliquids in one or more F-T reactors; separating the F-T liquids in aseparation system into heavy F-T liquids (HFTL) and medium F-T liquids(MFTL); and upgrading the separated F-T liquids in an upgrading systemcomprising a hydrotreating/hydrocracking reactor and fractionationsystem configured to upgrade the HFTL and MFTL into a transportationfuel.
 9. A process for producing Fischer-Tropsch (F-T) liquids derivedfrom municipal solid wastes(MSW) that contain materials that areproduced from biogenic derived carbon materials and non-biogenic derivedcarbon materials, the process comprising the steps of: a) in a feedstockprocessing step, removing some of the non-biogenic derived carbonmaterials and non-carbonaceous materials from the municipal solid wastesto produce a processed MSW feedstock that contains a higherconcentration of biogenic carbon materials than non-biogenic carbonmaterials; and b) converting the processed MSW feedstock intoFischer-Tropsch liquids in a bio-refinery while maintaining a greaterconcentration of biogenic carbon than non-biogenic carbon.
 10. Theprocess according to claim 9, wherein the converting step is comprisedof three stages carried out in a gasification island: 1) steam reformingthe processed feedstock in a steam reformer configured to dry,volatilize and gasify the processed feedstock to produce syngascontaining CO, H₂, H₂O and CO₂, unreacted char, inert solids andunreacted hydrocarbons; 2) further gasifying in a sub-stoichiometriccarbon oxidation unit configured to gasify the unreacted char from thesteam reformer; and 3) hydrocarbon reforming in a hydrocarbon reformingunit configured to convert remaining char, hydrocarbons and tars intosyngas.
 11. The process according to claim 10, further comprising:conditioning the syngas in a syngas conditioning unit configured toreceive the syngas from the gasification island and remove contaminants,remove/recover CO₂ and provide a high biogenic CO₂ recycle stream forrecycling high biogenic CO₂ to the gasification island for biogeniccarbon conservation and to adjust the H₂:CO₂ ratio in the syngas to apredetermined value; and converting the syngas into Fisher-Tropschliquids in one or more F-T reactors.
 12. The process according to claim9 wherein in the feedstock processing step, more than about 10% of thenon-biogenic derived carbon materials are removed.
 13. The processaccording to claim 9 wherein in the feedstock processing step, up toabout 80% of the non-biogenic derived carbon materials are removed. 14.The process according to claim 9 wherein in the feedstock processingstep, between about 10% and 90% of the non-biogenic derived carbonmaterials are removed.
 15. The process according to claim 9, furthercomprising the step of: in a power generation process, converting someor all of the biogenic carbon material into biogenic carbon derivedpower.